Methods and systems for correction of oil-based mud filtrate contamination on saturation pressure

ABSTRACT

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. In some embodiments, OBM filtrate contamination may be determined from downhole saturation pressure measurements during pumpout of a fluid.

CROSS-REFERENCES TO RELATED APPLICATIONS

The present application is a Divisional of co-pending U.S. patentapplication Ser. No. 16/531,640 filed Aug. 5, 2019, which in turn is aDivisional of application of U.S. patent application Ser. No. 14/535,199filed Nov. 6, 2014 and granted as U.S. Pat. No. 10,371,690 which areincorporated in their entirety by reference herein.

FIELD OF THE DISCLOSURE

This disclosure relates to downhole fluid monitoring, and, moreparticularly to methods and systems for correction of oil-based mudfiltrate contamination on saturation pressure.

BACKGROUND

This disclosure relates to determination of fluid properties usingdownhole fluid analysis (DFA). Fluid properties like gas-oil ratio(GOR), density, optical density (OD), composition, and others may bemeasured, detected, and/or estimated for fluids downhole in a well.Oil-based drilling mud (OBM) filtrate contamination may affect the fluidproperties measured downhole, and obtaining fluid samples having zeroOBM filtrate contamination may be difficult. The accuracy of such fluidproperties may affect reservoir development, production, and management.

SUMMARY

A summary of certain embodiments disclosed herein is set forth below.

It should be understood that these aspects are presented merely toprovide the reader with a brief summary of these certain embodiments andthat these aspects are not intended to limit the scope of thisdisclosure. Indeed, this disclosure may encompass a variety of aspectsthat may not be set forth below.

Embodiments of this disclosure relate to various methods and systems forcorrection of oil-based mud filtrate contamination on saturationpressure. In particular, certain embodiments of the disclosure caninclude methods and systems for determining saturation pressure of anuncontaminated fluid. According to some embodiments, a method isprovided that can include obtaining, by using at least one property of acontaminated fluid measured downhole by a downhole tool, oil-based mud(OBM) filtrate contamination of the contaminated fluid. The contaminatedfluid includes uncontaminated fluid and the OBM filtrate. The method canfurther include obtaining downhole saturation pressure measurements ofthe reservoir fluid and determining a relationship between the downholesaturation pressure measurements and the OBM filtrate contamination. Themethod can also include extrapolating the determined relationshipbetween the downhole saturation pressure measurements and the OBMfiltrate contamination to a zero OBM filtrate contamination anddetermining a saturation pressure of the uncontaminated fluid at thezero OBM filtrate contamination.

According to another embodiment, a system is provided that can include adownhole tool operable within a wellbore extending into a subterraneanformation, a controller coupled to the downhole tool, and anon-transitory tangible machine-readable memory coupled to a processorof the controller. The non-transitory tangible machine-readable memorystores machine-readable instructions that when executed by the processorcause the processor to perform operations that can include obtaining, byusing at least one property of a contaminated fluid measured downhole bya downhole tool, oil-based mud (OBM) filtrate contamination of thecontaminated fluid. The contaminated fluid can include uncontaminatedfluid and the OBM filtrate. Additionally, the non-transitory tangiblemachine-readable memory stores machine-readable instructions that whenexecuted by the processor cause the processor to perform operations thatcan further include obtaining downhole saturation pressure measurementsof the reservoir fluid and determining a relationship between thedownhole saturation pressure measurements and the OBM filtratecontamination. The non-transitory tangible machine-readable memory alsostores machine-readable instructions that when executed by the processorcause the processor to perform operations that can include extrapolatingthe determined relationship between the downhole saturation pressuremeasurements and the OBM filtrate contamination to a zero OBM filtratecontamination and determining a saturation pressure of theuncontaminated fluid at the zero OBM filtrate contamination.

Further, embodiments of this disclosure relate to various methods andsystems for determining OBM filtrate contamination of a contaminatedfluid. According to some embodiments, a method is provided that caninclude measuring downhole saturation pressures of a contaminated fluidover a pumpout volume or a pumpout time, the contaminated fluidincluding uncontaminated fluid and an OBM filtrate. The method canfurther include determining a function for the measured saturationpressures based on the pumpout volume or pumpout time and extrapolatingthe function to infinite pumpout volume or infinite pumpout time.Additionally, the method can include determining a saturation pressurefor the uncontaminated fluid at the infinite pumping volume or infinitepumping time and obtaining a saturation pressure of the OBM filtrate.The method can also include determining an OBM filtrate contamination ofthe contaminated fluid based on the saturation pressure for theuncontaminated fluid, the saturation pressure for the OBM filtrate, andthe measured saturation pressure for the contaminated fluid.

According to another embodiments, a system is provided that includes adownhole tool operable within a wellbore extending into a subterraneanformation, a controller coupled to the downhole tool, and anon-transitory tangible machine-readable memory coupled to a processorof the controller. The non-transitory tangible machine-readable memorystores machine-readable instructions that when executed by the processorcause the processor to perform operations that can include measuringdownhole saturation pressures of a contaminated fluid over a pumpoutvolume or a pumpout time, the contaminated fluid includinguncontaminated fluid and an OBM filtrate. Additionally, thenon-transitory tangible machine-readable memory stores machine-readableinstructions that when executed by the processor cause the processor toperform operations that can further include further includes determininga function for the measured saturation pressures based on the pumpoutvolume or pumpout time and extrapolating the function to infinitepumpout volume or infinite pumpout time. The non-transitory tangiblemachine-readable memory stores machine-readable instructions that whenexecuted by the processor cause the processor to perform operations thatcan further include determining a saturation pressure for theuncontaminated fluid at the infinite pumping volume or infinite pumpingtime and obtaining a saturation pressure of the OBM filtrate. Further,the non-transitory tangible machine-readable memory storesmachine-readable instructions that when executed by the processor causethe processor to perform operations that can further include determiningan OBM filtrate contamination of the contaminated fluid based on thesaturation pressure for the uncontaminated fluid, the saturationpressure for the OBM filtrate, and the measured saturation pressure forthe contaminated fluid.

Various refinements of the features noted above may be undertaken inrelation to various aspects of the present disclosure. Further featuresmay also be incorporated in these various aspects as well. Theserefinements and additional features may be determined individually or inany combination. For instance, various features discussed below inrelation to the illustrated embodiments may be incorporated into any ofthe above-described aspects of the present disclosure alone or in anycombination. The brief summary presented above is intended tofamiliarize the reader with certain aspects and contexts of embodimentsof the present disclosure without limitation to the claimed subjectmatter.

BRIEF DESCRIPTION OF THE DRAWINGS

Various aspects of this disclosure may be better understood upon readingthe following detailed description and upon reference to the drawings inwhich:

FIG. 1 generally depicts a drilling system having a fluid sampling toolin a drill string in accordance with an embodiment of the presentdisclosure;

FIG. 2 generally depicts a fluid sampling tool deployed within a well ona wireline in accordance with an embodiment of the present disclosure;

FIG. 3 is a block diagram of components of a fluid sampling tooloperated by a controller in accordance with an embodiment of the presentdisclosure;

FIGS. 4-6 are plots of saturation pressure vs. OBM filtratecontamination in accordance with an embodiment of the presentdisclosure;

FIG. 7 is a block diagram of a process for determining saturationpressure of an uncontaminated fluid in accordance with an embodiment ofthe present disclosure;

FIG. 8 is a plot of optical density and OBM filtrate contamination vs.pumping time in accordance with an embodiment of the present disclosure;

FIG. 9 is plot of measured bubble point pressures and OBM filtratecontamination vs. pumping time in accordance with an embodiment of thepresent disclosure;

FIG. 10 is a plot of a linear function for measured bubble pointpressures vs. OBM filtrate contamination in accordance with anembodiment of the present disclosure;

FIG. 11 is a block diagram of a process for determining OBM filtratecontamination from measured bubble point pressures in accordance with anembodiment of the present disclosure; and

FIG. 12 is a block diagram of a processing system in accordance with anembodiment of the present disclosure.

DETAILED DESCRIPTION

Described herein are various embodiments related to the determination ofsaturation pressure of an uncontaminated fluid using downhole saturationpressure measurements of a contaminated fluid and OBM filtratecontamination. As used herein, the saturation pressure may refer to adew point pressure or a bubble point pressure. In some embodiments,downhole OBM filtrate contamination and downhole saturation pressuremeasurements of a contaminated fluid may be obtained. In someembodiments, a regression (e.g., a linear regression) may be performedon a plot of downhole saturation pressure measurements vs. OBM filtratecontamination to determine a linear function. The function (e.g., alinear function) may be extrapolated to zero OBM filtrate contaminationto determine the saturation pressure (bubble point pressure or dew pointpressure) of the uncontaminated fluid.

Also described herein are embodiments related to the determination ofOBM filtrate contamination from downhole saturation pressuremeasurements. In some embodiments, downhole saturation pressure, such asbubble point pressures, may be measured during a pumpout volume or time.A function (e.g., a power function) for the saturation pressure vs.pumpout volume or time may be fitted, and the function may beextrapolated to infinite volume or infinite time to obtain a bubblepoint pressure for the uncontaminated fluid. The OBM filtrate saturationpressure may also be obtained. The OBM filtrate contamination may bedetermined using the saturation pressure for the uncontaminated fluid,the saturation pressure for the OBM filtrate, and the measuredsaturation pressure for the contaminated fluid.

These and other embodiments of the disclosure will be described in moredetail through reference to the accompanying drawings in the detaileddescription of the disclosure that follows. This brief introduction,including section titles and corresponding summaries, is provided forthe reader's convenience and is not intended to limit the scope of theclaims or the proceeding sections. Furthermore, the techniques describedabove and below may be implemented in a number of ways and in a numberof contexts. Several example implementations and contexts are providedwith reference to the following figures, as described below in moredetail. However, the following implementations and contexts are but afew of many.

More specifically, a drilling system 10 is depicted in FIG. 1 inaccordance with one embodiment. While certain elements of the drillingsystem 10 are depicted in this figure and generally discussed below, itwill be appreciated that the drilling system 10 may include othercomponents in addition to, or in place of, those presently illustratedand discussed. As depicted, the system 10 can include a drilling rig 12positioned over a well 14. Although depicted as an onshore drillingsystem 10, it is noted that the drilling system could instead be anoffshore drilling system. The drilling rig 12 can support a drill string16 that includes a bottomhole assembly 18 having a drill bit 20. Thedrilling rig 12 can rotate the drill string 16 (and its drill bit 20) todrill the well 14.

The drill string 16 can be suspended within the well 14 from a hook 22of the drilling rig 12 via a swivel 24 and a kelly 26. Although notdepicted in FIG. 1 , the skilled artisan will appreciate that the hook22 can be connected to a hoisting system used to raise and lower thedrill string 16 within the well 14. As one example, such a hoistingsystem could include a crown block and a drawworks that cooperate toraise and lower a traveling block (to which the hook 22 is connected)via a hoisting line. The kelly 26 can be coupled to the drill string 16,and the swivel 24 can allow the kelly 26 and the drill string 16 torotate with respect to the hook 22. In the presently illustratedembodiment, a rotary table 28 on a drill floor 30 of the drilling rig 12can be constructed to grip and turn the kelly 26 to drive rotation ofthe drill string 16 to drill the well 14. In other embodiments, however,a top drive system could instead be used to drive rotation of the drillstring 16.

During operation, drill cuttings or other debris may collect near thebottom of the well 14. Drilling fluid 32, also referred to as drillingmud, can be circulated through the well 14 to remove this debris. Thedrilling fluid 32 may also clean and cool the drill bit 20 and providepositive pressure within the well 14 to inhibit formation fluids fromentering the wellbore. In FIG. 1 , the drilling fluid 32 can becirculated through the well 14 by a pump 34. The drilling fluid 32 canbe pumped from a mud pit (or some other reservoir, such as a mud tank)into the drill string 16 through a supply conduit 36, the swivel 24, andthe kelly 26. The drilling fluid 32 can exit near the bottom of thedrill string 16 (e.g., at the drill bit 20) and can return to thesurface through the annulus 38 between the wellbore and the drill string16. A return conduit 40 can transmit the returning drilling fluid 32away from the well 14. In some embodiments, the returning drilling fluid32 can be cleansed (e.g., via one or more shale shakers, desanders, ordesilters) and reused in the well 14. The drilling fluid 32 may includean oil-based mud (OBM) that may include synthetic muds, diesel-basedmuds, or other suitable muds.

In addition to the drill bit 20, the bottomhole assembly 18 can alsoinclude various instruments that measure information of interest withinthe well 14. For example, as depicted in FIG. 1 , the bottomholeassembly 18 can include a logging-while-drilling (LWD) module 44 and ameasurement-while-drilling (MWD) module 46. Both modules can includesensors, housed in drill collars, that can collect data and enable thecreation of measurement logs in real-time during a drilling operation.The modules could also include memory devices for storing the measureddata. The LWD module 44 can include sensors that measure variouscharacteristics of the rock and formation fluid properties within thewell 14. Data collected by the LWD module 44 could include measurementsof gamma rays, resistivity, neutron porosity, formation density, soundwaves, optical density, and the like. The MWD module 46 can includesensors that measure various characteristics of the bottomhole assembly18 and the wellbore, such as orientation (azimuth and inclination) ofthe drill bit 20, torque, shock and vibration, the weight on the drillbit 20, and downhole temperature and pressure. The data collected by theMWD module 46 can be used to control drilling operations. The bottomholeassembly 18 can also include one or more additional modules 48, whichcould be LWD modules, MWD modules, or some other modules. It is notedthat the bottomhole assembly 18 is modular, and that the positions andpresence of particular modules of the assembly could be changed asdesired. Further, as discussed in detail below, one or more of themodules 44, 46, and 48 can be or can include a fluid sampling toolconfigured to obtain a sample of a fluid from a subterranean formationand perform downhole fluid analysis to measure various properties of thesampled fluid. These properties may include an estimated density and/oroptical density of the OBM filtrate, the sampled fluid, and otherfluids. These and other estimated properties may be determined within orcommunicated to the LWD module 44, such as for subsequent utilization asinput to various control functions and/or data logs.

The bottomhole assembly 18 can also include other modules. As depictedin FIG. 1 by way of example, such other modules can include a powermodule 50, a steering module 52, and a communication module 54. In oneembodiment, the power module 50 can include a generator (such as aturbine) driven by flow of drilling mud through the drill string 16. Inother embodiments, the power module 50 could also or instead includeother forms of power storage or generation, such as batteries or fuelcells. The steering module 52 may include a rotary-steerable system thatfacilitates directional drilling of the well 14. The communicationmodule 54 can enable communication of data (e.g., data collected by theLWD module 44 and the MWD module 46) between the bottomhole assembly 18and the surface. In one embodiment, the communication module 54 cancommunicate via mud pulse telemetry, in which the communication module54 uses the drilling fluid 32 in the drill string as a propagationmedium for a pressure wave encoding the data to be transmitted.

The drilling system 10 can also include a monitoring and control system56. The monitoring and control system 56 can include one or morecomputer systems that enable monitoring and control of variouscomponents of the drilling system 10. The monitoring and control system56 can also receive data from the bottomhole assembly 18 (e.g., datafrom the LWD module 44, the MWD module 46, and the additional module 48)for processing and for communication to an operator, to name just twoexamples. While depicted on the drill floor 30 in FIG. 1 , it is notedthat the monitoring and control system 56 could be positioned elsewhere,and that the system 56 could be a distributed system with elementsprovided at different places near or remote from the well 14.

Another example of using a downhole tool for formation testing withinthe well 14 is depicted in FIG. 2 . In this embodiment, a fluid samplingtool 62 can be suspended in the well 14 on a cable 64. The cable 64 maybe a wireline cable with at least one conductor that enables datatransmission between the fluid sampling tool 62 and a monitoring andcontrol system 66. The cable 64 may be raised and lowered within thewell 14 in any suitable manner. For instance, the cable 64 can be reeledfrom a drum in a service truck, which may be a logging truck having themonitoring and control system 66. The monitoring and control system 66can control movement of the fluid sampling tool 62 within the well 14and can receive data from the fluid sampling tool 62. In a similarfashion to the monitoring and control system 56 of FIG. 1 , themonitoring and control system 66 may include one or more computersystems or devices and may be a distributed computing system. Thereceived data can be stored, communicated to an operator, or processed,for instance. While the fluid sampling tool 62 is here depicted as beingdeployed by way of a wireline, in some embodiments the fluid samplingtool 62 (or at least its functionality) can be incorporated into or asone or more modules of the bottomhole assembly 18, such as the LWDmodule 44 or the additional module 48.

The fluid sampling tool 62 can take various forms. While it is depictedin FIG. 2 as having a body including a probe module 70, a fluid analysismodule 72, a pump module 74, a power module 76, and a fluid storagemodule 78, the fluid sampling tool 62 may include different modules inother embodiments. The probe module 70 can include a probe 82 that maybe extended (e.g., hydraulically driven) and pressed into engagementagainst a wall 84 of the well 14 to draw fluid from a formation into thefluid sampling tool 62 through an intake 86. As depicted, the probemodule 70 can also include one or more setting pistons 88 that may beextended outwardly to engage the wall 84 and push the end face of theprobe 82 against another portion of the wall 84. In some embodiments,the probe 82 can include a sealing element or packer that isolates theintake 86 from the rest of the wellbore. In other embodiments, the fluidsampling tool 62 could include one or more inflatable packers that canbe extended from the body of the fluid sampling tool 62 tocircumferentially engage the wall 84 and isolate a region of the well 14near the intake 86 from the rest of the wellbore. In such embodiments,the extendable probe 82 and setting pistons 88 could be omitted and theintake 86 could be provided in the body of the fluid sampling tool 62,such as in the body of a packer module housing an extendable packer.

The pump module 74 can draw the sampled formation fluid into the intake86, through a flowline 92, and then either out into the wellbore throughan outlet 94 or into a storage container (e.g., a bottle within fluidstorage module 78) for transport back to the surface when the fluidsampling tool 62 is removed from the well 14. The fluid analysis module72, which may also be referred to as the fluid analyzer 72 or a DFAmodule, can include one or more sensors for measuring properties of thesampled formation fluid, such as the optical density of the fluid, andthe power module 76 provides power to electronic components of the fluidsampling tool 62. In some embodiments, the fluid analysis module 72 mayinclude a downhole pressure-volume-temperature PVT unit and may obtainmicrofluidic measurements. In such embodiments, the fluid analysismodule 72 may be referred to as a DFA microfluidics module. Themeasurements may be utilized to estimate a formation volume factor ofthe contaminated formation fluid, as well as density, optical density,GOR, compressibility, saturation pressure, viscosity, and/or massfractions of compositional components of the contaminated formationfluid and/or contaminants therein (e.g., OBM filtrate), among others.

The drilling and wireline environments depicted in FIGS. 1 and 2 areexamples of environments in which a fluid sampling tool may be used tofacilitate analysis of a downhole fluid. The presently disclosedtechniques, however, could be implemented in other environments as well.For instance, the fluid sampling tool 62 may be deployed in othermanners, such as by a slickline, coiled tubing, or a pipe string.

Additional details as to the construction and operation of the fluidsampling tool 62 may be better understood through reference to FIG. 3 .As shown in this figure, various components for carrying out functionsof the fluid sampling tool 62 can be connected to a controller 100. Thevarious components can include a hydraulic system 102 connected to theprobe 82 and the setting pistons 88, a spectrometer 104 for measuringfluid optical properties, one or more other sensors 106, a pump 108, andvalves 112 for diverting sampled fluid into storage devices 110 ratherthan venting it through the outlet 94. The controller 100 may include orbe coupled to an operator interface (not shown) that provides logs ofpredicted formation fluid properties that are accessible to an operator.

In operation, the hydraulic system 102 can extend the probe 82 and thesetting pistons 88 to facilitate sampling of a formation fluid throughthe wall 84 of the well 14. It also can retract the probe 82 and thesetting pistons 88 to facilitate subsequent movement of the fluidsampling tool 62 within the well. The spectrometer 104, which can bepositioned within the fluid analyzer 72, can collect data about opticalproperties of the sampled formation fluid. Such measured opticalproperties can include optical densities (absorbance) of the sampledformation fluid at different wavelengths of electromagnetic radiation.Using the optical densities, the composition of a sampled fluid (e.g.,volume fractions of its constituent components) can be determined. Othersensors 106 can be provided in the fluid sampling tool 62 (e.g., as partof the probe module 70 or the fluid analyzer 72) to take additionalmeasurements related to the sampled fluid. In various embodiments, theseadditional measurements could include reservoir pressure andtemperature, live fluid density, live fluid viscosity, electricalresistivity, saturation pressure, and fluorescence, to name severalexamples. In some embodiments, as mentioned above, some or all of othersensors 106 may be incorporated into a DFA module (e.g., such as in aPVT unit) of the fluid sampling tool 62. Other characteristics, such asgas-to-oil ratio (GOR), may also be determined using the DFAmeasurements.

Any suitable pump 108 may be provided in the pump module 74 to enableformation fluid to be drawn into and pumped through the flowline 92 inthe manner discussed above. Storage devices 110 for formation fluidsamples can include any suitable vessels (e.g., bottles) for retainingand transporting desired samples within the fluid sampling tool 62 tothe surface. Both the storage devices 110 and the valves 112 may beprovided as part of the fluid storage module 78.

In the embodiment depicted in FIG. 3 , the controller 100 can facilitateoperation of the fluid sampling tool 62 by controlling variouscomponents. Specifically, the controller 100 can direct operation (e.g.,by sending command signals) of the hydraulic system 102 to extend andretract the probe 82 and the setting pistons 88 and of the pump 108 todraw formation fluid samples into and through the fluid sampling tool.The controller 100 can also receive data from the spectrometer 104 andthe other sensors 106. This data can be stored by the controller 100 orcommunicated to another system (e.g., the monitoring and control system56 or 66) for analysis. In some embodiments, the controller 100 isitself capable of analyzing the data it receives from the spectrometer104 and the other sensors 106. The controller 100 can also operate thevalves 112 to divert sampled fluids from the flowline 92 into thestorage devices 110.

The various fluid properties mentioned above and measured by the toolsdescribed herein may be affected by OBM filtrate contamination in thesampled fluid (referred to as “contaminated” fluid). For example,measured saturation pressures, such as measured by a downhole PVT unitof a DFA module, may be affected by OBM filtrate contamination and maynot accurately reflect the saturation pressure of the uncontaminatedfluid. The saturation pressures may increase or decrease with anincrease in OBM filtrate contamination.

By way of example, FIGS. 4-6 depict plots of saturation pressure vs. OBMfiltrate contamination (as a volume fraction expressed as percentage)data points indicating a relationship between saturation pressures, suchas bubble point pressure or dew point pressure, and OBM filtratecontamination. FIG. 4 depicts a plot 400 of the bubble point pressure ofheavy oil vs. volume fraction of various OBM filtrate contaminates(esters, mineral oil, and olefins). FIG. 5 depicts a plot 500 ofmeasured bubble point pressure of black oil vs. volume fraction ofvarious OBM filtrate contaminates (esters, mineral oil, and olefins).Similarly, FIG. 6 depicts a plot 600 of measured dew point pressure ofgas condensate vs. volume fractions of various OBM filtrate contaminates(esters, mineral oil, and olefins). As shown in FIGS. 4-6 , for an OBMfiltrate contamination below a certain amount, the bubble point and dewpoint pressures are approximately a linear function of the OBM filtratecontamination, regardless of whether the bubble point and dew pointincrease or decrease relative to increased OBM filtrate contamination.In some embodiments, as shown in FIGS. 4-6 , a linear function may beused to approximate the relationship between saturation pressure and OBMfiltrate contaminations below about 40% volume. However, it should beappreciated that the slope of each linear approximation function varieswith the composition of the OBM filtrate and the composition of thefluid. Thus, in other embodiments, a linear function may be used toapproximate the relationship between saturation pressure and OBMfiltrate contaminations about 10% volume or less, 20% volume or less,30% volume or less, 40% volume or less, or other suitable OBMcontamination obtained from saturation pressure and OBM filtratecontamination data.

In view of the linear function approximations discussed above, thesaturation pressure of a contaminated fluid may be expressed as followsby Equation 1:

$\begin{matrix}{P^{sat} = {{v_{obm}P_{obm}^{hypo}} + {\left( {1 - v_{obm}} \right)P_{0}^{sat}}}} & (1)\end{matrix}$

Where, P^(sat) is the saturation pressure of the contaminated fluid,v_(obm) is the OBM filtrate contamination in volume fraction of thecontaminated fluid as measured by a downhole tool, P₀ ^(sat) is thesaturation pressure of the uncontaminated (also referred to as “native”)fluid, and P_(obm) ^(hypo) is the hypothetical OBM filtrate saturationpressure. The hypothetical OBM filtrate saturation pressure may be usedinstead of the real OBM filtrate saturation pressure; because no gas isdissolved and the OBM filtrate is typically heavier than C₇, the realOBM filtrate saturation pressure is nearly zero. Additionally, using thehypothetical OBM filtrate saturation enables use of a linear functionover a linear range of contamination, as the relationship of saturationpressure to OBM filtrate contamination may be non-linear at highercontamination.

By factoring v_(obm), Equation 1 may be rewritten as Equation 2 below:

$\begin{matrix}{P^{sat} = {{\left( {P_{obm}^{hypo} - P_{0}^{sat}} \right)v_{obm}} + P_{0}^{sat}}} & (2)\end{matrix}$

As mentioned, at relatively low OBM filtrate contamination, thesaturation pressure is a linear function of OBM filtrate contamination.The slope of the line of such a linear function is P_(obm) ^(hypo)−P₀^(sat) and the y-axis intercept at a value of zero OBM filtrateconcentration is P₀ ^(sat). Thus, as described herein, saturationpressures may be measured during cleanup at different OBM filtratecontamination levels and the linear relationship may be approximated byEquation 2 and used to obtain the P₀ ^(sat) of the uncontaminated fluid.

FIG. 7 depicts a process for determining the saturation pressure (bubblepoint pressure or dew point pressure) of an uncontaminated fluid inaccordance with the techniques described herein. The process may beperformed using a downhole tool having a DFA module, such as thatdescribed above. As will be appreciated, the determination described inprocess 700 is executed on a downhole fluid sample, thus eliminating theneed to preserve fluid samples and transport samples to the surface and,in some instances, to a laboratory for further analysis. The downholefluid sample may be obtained by initiating a pumpout of contaminatedfluid, such as during cleanup of a well.

Downhole OBM filtrate contamination (v_(obm)) may be obtained (block702) by various suitable techniques. In some embodiments, propertiessuch as optical density, gas/oil ratio, mass density, pumpout volume,pumpout time, and the like may be measured during pumpout and cleanoutusing a DFA apparatus. In such embodiments, OBM filtrate concentrationmay be determined by DFA OBM filtrate concentration (OCM) techniques,such as those described in U.S. Pat. Nos. 6,956,204 and 8,204,125. Insome embodiments, the OBM filtrate concentration may be determinedaccording to the techniques described in U.S. application Ser. No.14/085,589, entitled “Method and Apparatus for Consistent and RobustFitting in Oil-Based Mud Filtrate Contamination Monitoring for MultipleDownhole Sensors”, now U.S. Pat. No. 10,316,655, a copy of which isherein incorporated by reference. Next, downhole saturation pressuremeasurements of the contaminated fluid may be obtained (block 704). Insome embodiments, downhole saturation pressure measurements may beobtained using a downhole PVT unit of a DFA module.

In some embodiments, the additional operations of process 700 may beperformed after a threshold OBM filtrate contamination is reached. Insuch embodiments, OBM filtrate contamination may be continuouslydetermined during pumpout of the contaminated fluid until sufficientfluid has been pumped to reach a desired OBM filtrate contamination. Forexample, in some embodiments the additional operations of the process700 may be performed after a threshold OBM filtrate contamination ofabout 10% volume or less, 20% volume or less, 30% volume or less, 40%volume or less, or other suitable OBM contamination volume.

Next, a plot of the measured downhole saturation pressures vs. OBMfiltrate contamination may be generated (block 706). As discussed above,in some embodiments the bubble point pressure or the dew point pressuremay be plotted against the determined volume fraction of OBM filtratecontamination. Next, a linear regression may be performed on the datapoints of the plot to determine the linear relationship between themeasured saturation pressures and the OBM filtrate contamination (block708). As discussed above, the linear relationship may be expressedaccording to Equation 2 and the slope of the linear function may beP_(obm) ^(hypo)−P₀ ^(sat).

Next, the linear relationship may be extrapolated to a zero OBM filtratecontamination (block 710), e.g., a y-axis intercept, and the saturationpressure (bubble point pressure or dew point pressure) of theuncontaminated fluid may be determined (block 712). As will beappreciated, the process 700 described above may be performed for bubblepoint pressures or dew point pressures measured downhole.

Although the embodiments described above discuss determination of alinear relationship between saturation pressure and OBM filtratecontamination for certain volume fractions of OBM filtratecontamination, it should be appreciated that the linear relationship andlinear function are provided by way of example and other embodiments mayinclude a non-linear relationship. For example, some fluids and OBMmixtures may exhibit a non-linear relationship between saturationpressure and OBM filtrate contamination. In such embodiments, apolynomial or other non-linear function may be determined from a plot ofsaturation pressure vs. OBM filtrate contamination volume fraction, andthe process 700 described above may be performed using a non-linearfunction instead of the linear function. Thus, in the manner describedabove, the non-linear function may be extrapolated to zero OBM filtrateto determine the saturation pressure of the uncontaminated fluid.

FIGS. 8-10 depict different plots illustrating an example of thetechniques described above for determining saturation pressure of anuncontaminated fluid. FIG. 8 depicts a plot 800 of optical density (asmeasured using a DFA module) 802 and OBM filtrate contamination 804 as afunction of pumping time during a downhole cleanup process for crudeoil. As shown in the plot 800, the optical density decreases 802 withtime. After the OBM filtrate contamination reaches a certain level,downhole saturation pressures may begin to be measured using, forexample, a DFA module. FIG. 9 depicts a plot 900 of measured bubblepoint pressures 902 and OBM filtrate contamination 904 as a function ofpumping time. As shown in FIG. 9 , the bubble point pressure increasesas the pumping time increases; however, the bubble point pressure curve906 begins to flatten out as the pumping time increases, as illustratedby portion 908.

FIG. 10 depicts a plot 1000 of data points 1002 of measured bubble pointpressure vs. OBM filtrate contamination, such as described above inblock 708. As shown in FIG. 8 , a linear regression may be used todetermine a linear relationship (e.g., linear function 1004) for thedata points 1002. As mentioned above, the slope of the line of thelinear relationship 1004 may be P_(obm) ^(hypo)−P₀ ^(sat). The linearrelationship 1004 may be extrapolated to zero OBM filtratecontamination, e.g., to intercept the y-axis of the plot 1000, asillustrated by point 1006 in FIG. 10 . The bubble point pressure of theuncontaminated fluid may be determined at point 1006 (e.g.,approximately 4375 psi).

In some embodiments, the flatness of the saturation pressure curve maybe used as indication of OBM filtrate contamination. For example, asdepicted in FIG. 8 , as pumping time increases, the bubble pointpressure curve 906 flattens out, as shown by portion 908. If the bubblepoint pressure curve 906 is flat (or its derivative is zero), the OBMfiltrate contamination may be equal to or nearly zero.

In some embodiments, the OBM filtrate contamination may be determinedusing an observed bubble point pressure curve during a pumpout. Equation1 described above may be rewritten to determine OBM filtratecontamination, as expressed below in Equation 3:

$\begin{matrix}{v_{obm} = {\alpha\frac{P_{0}^{sat} - P^{sat}}{P_{0}^{sat} - P_{obm}^{hypo}}}} & (3)\end{matrix}$

Where P^(sat) is the saturation pressure of the contaminated fluid asmeasured downhole (e.g., via a DFA apparatus), P_(obm) ^(hypo) is thehypothetical OBM saturation pressure and may be assumed to be equal tozero for crude oil or, in some embodiments, may be an adjusted parameterbased on the fluid and OBM filtrate, P₀ ^(sat) is the saturationpressure of the uncontaminated fluid, and α is a constant that dependson the properties of the OBM filtrate and the reservoir fluid. In someembodiments, a may be assumed to 1. In other embodiments, α may bedetermined from another fluid property that follows a lever rule, suchas density. For example, in such embodiments, a may be calculated fromthe volume contamination from the density at two points and the relativecontamination from the bubble point pressure at two points. The measuredP^(sat) may be fitted using the power function described below inEquation 4:

$\begin{matrix}{P^{sat} = {P_{0}^{sat} - {\beta\; V^{- \gamma}}}} & (4)\end{matrix}$

Where V is the measured pumpout volume (e.g., as measured by a DFAmodule) and P₀ ^(sat), β and γ, are adjustable parameters. In someembodiments, the power function described in Equation 4 may be expressedusing the pumpout time t to replace the measured pumpout volume V. Inother embodiments, other function for the saturation pressure may befitted.

FIG. 11 depicts a process 1100 for determining OBM filtratecontamination based on measured downhole bubble point pressures inaccordance with an embodiment of the present technique. The process maybe performed using a downhole tool having a DFA module, such as thetools described above. As will be appreciated, the determinationdescribed in process 1100 is executed on a downhole fluid sample, thuseliminating the need to preserve fluid samples and transport samples tothe surface and, in some instances, to a laboratory for furtheranalysis.

Initially, downhole bubble point pressures of a fluid and pumpout volumeor time may be measured (block 1102) during pumpout of contaminatedfluid, such as during cleanup of a well. Next, the power function forbubble point pressure as a function of pumpout volume, as described byEquation 4, may be fitted to the measured bubble point pressure curve(block 1104). In other embodiments, as mentioned above, the pumpout timet may be used instead of the pumpout volume V and a corresponding powerfunction of bubble point pressure as a function of pumpout time t may befitted.

Next, the fitted power function may be extrapolated to infinite volumeV, or, in some embodiments, infinite time t (block 1106), and the bubblepoint pressure for the uncontaminated fluid may be determined from thebubble point pressure at infinite volume V or infinite time t (block1108). As described above, the OBM filtrate bubble point pressure may beobtained (block 1111). In some embodiments, the OBM filtrate bubblepoint pressure may be assumed to equal zero. In other embodiments, theOBM filtrate bubble point pressure may be obtained by fitting dataobtained from another source, such as another well using the OBMfiltrate. In other embodiments, the OBM filtrate bubble point pressuremay be the hypothetical OBM filtrate saturation pressure, as described.Next, the OBM filtrate contamination may be determined using Equation 3(block 1112). In some embodiments, the OBM filtrate contamination may bemonitored to obtain a desired sample of the fluid in a downhole tool.

FIG. 12 is a block diagram of an example processing system 1200 that mayexecute example machine-readable instructions used to implement one ormore of processes described herein and, in some embodiments, toimplement a portion of one or more of the example downhole toolsdescribed herein. The processing system 1000 may be or include, forexample, controllers (e.g., controller 100), special-purpose computingdevices, servers, personal computers, personal digital assistant (PDA)devices, tablet computers, wearable computing devices, smartphones,internet appliances, and/or other types of computing devices. Moreover,while it is possible that the entirety of the system 1200 shown in FIG.17 is implemented within a downhole tool, it is also contemplated thatone or more components or functions of the system 1200 may beimplemented in wellsite surface equipment. As shown in the embodimentillustrated in FIG. 12 , the processing system 1200 may include one ormore processors (e.g., processors 1202A-1202N), a memory 1204, I/O ports1206 input devices 1208, output devices 1210, and a network interface1214. The process system 1200 may also include one or more additionalinterfaces 1214 to facilitate communication between the variouscomponents of the system 1200.

The processor 1202 may provide the processing capability to executeprograms, user interfaces, and other functions of the system 1200. Theprocessor 1202 may include one or more processors and may include“general-purpose” microprocessors, special purpose microprocessors, suchas application-specific integrated circuits (ASICs), or any combinationthereof. In some embodiments, the processor 1202 may include one or morereduced instruction set (RISC) processors, such as those implementingthe Advanced RISC Machine (ARM) instruction set. Additionally, theprocessor 1202 may include single-core processors and multicoreprocessors and may include graphics processors, video processors, andrelated chip sets. Accordingly, the system 1200 may be a uni-processorsystem having one processor (e.g., processor 1202 a), or amulti-processor system having two or more suitable processors (e.g.,1202A-1202N). Multiple processors may be employed to provide forparallel or sequential execution of the techniques described herein.Processes, such as logic flows, described herein may be performed by theprocessor 1202 executing one or more computer programs to performfunctions by operating on input data and generating correspondingoutput. The processor 1202 may receive instructions and data from amemory (e.g., memory 1204).

The memory 1204 (which may include one or more tangible non-transitorycomputer readable storage mediums) may include volatile memory andnon-volatile memory accessible by the processor 1202 and othercomponents of the system 1200. For example, the memory 1204 may includevolatile memory, such as random access memory (RAM). The memory 1204 mayalso include non-volatile memory, such as ROM, flash memory, a harddrive, other suitable optical, magnetic, or solid-state storage mediumsor any combination thereof. The memory 1204 may store a variety ofinformation and may be used for a variety of purposes. For example, thememory 1204 may store executable computer code, such as the firmware forthe system 1200, an operating system for the system 1200, and any otherprograms or other executable code for providing functions of the system1200. Such executable computer code may include program instructions1218 executable by a processor (e.g., one or more of processors1202A-1202N) to implement one or more embodiments of the presentdisclosure. Program instructions 1218 may include computer programinstructions for implementing one or more techniques described herein.Program instructions 1218 may include a computer program (which incertain forms is known as a program, software, software application,script, or code).

The interface 1214 may include multiple interfaces and may enablecommunication between various components of the system 1200, theprocessor 1202, and the memory 1204. In some embodiments, the interface1214, the processor 1202, memory 1204, and one or more other componentsof the system 1200 may be implemented on a single chip, such as asystem-on-a-chip (SOC). In other embodiments, these components, theirfunctionalities, or both may be implemented on separate chips. Theinterface 1214 may enable communication between processors 1202 a-1202n, the memory 1204, the network interface 1210, or any other devices ofthe system 1200 or a combination thereof. The interface 1214 mayimplement any suitable types of interfaces, such as Peripheral ComponentInterconnect (PCI) interfaces, the Universal Serial Bus (USB)interfaces, Thunderbolt interfaces, Firewire (IEEE-1394) interfaces, andso on.

The system 1200 may also include an input and output port 1208 to enableconnection of additional devices, such as I/O devices 1214. Embodimentsof the present disclosure may include any number of input and outputports 1208, including headphone and headset jacks, universal serial bus(USB) ports, Firewire (IEEE-1394) ports, Thunderbolt ports, and AC andDC power connectors. Further, the system 1200 may use the input andoutput ports to connect to and send or receive data with any otherdevice, such as other portable computers, personal computers, printers,etc.

The processing system 1200 may include one or more input devices 1208.The input device(s) 1208 permit a user to enter data and commands usedand executed by the processor 1212. The input device 1208 may include,for example, a keyboard, a mouse, a touchscreen, a track-pad, atrackball, an isopoint, and/or a voice recognition system, among others.The processing system 1200 may also include one or more output devices1210. The output devices 1210 may include, for example, display devices(e.g., a liquid crystal display or cathode ray tube display (CRT), amongothers), printers, and/or speakers, among others.

The system 1200 depicted in FIG. 12 also includes a network interface1210. The network interface 1210 may include a wired network interfacecard (NIC), a wireless (e.g., radio frequency) network interface card,or combination thereof. The network interface 1210 may include knowncircuitry for receiving and sending signals to and from communicationsnetworks, such as an antenna system, an RF transceiver, an amplifier, atuner, an oscillator, a digital signal processor, a modem, a subscriberidentity module (SIM) card, memory, and so forth. The network interface1210 may communicate with networks (e.g., network 1216), such as theInternet, an intranet, a cellular telephone network, a wide area network(WAN), a local area network (LAN), a metropolitan area network (MAN), orother devices by wired or wireless communication using any suitablecommunications standard, protocol, or technology.

Conditional language, such as, among others, “can,” “could,” “might,” or“may,” unless specifically stated otherwise, or otherwise understoodwithin the context as used, is generally intended to convey that certainimplementations could include, while other implementations do notinclude, certain features, elements, and/or operations. Thus, suchconditional language is not generally intended to imply that features,elements, and/or operations are in any way used for one or moreimplementations or that one or more implementations necessarily includelogic for deciding, with or without user input or prompting, whetherthese features, elements, and/or operations are included or are to beperformed in any particular implementation.

Many modifications and other implementations of the disclosure set forthherein will be apparent having the benefit of the teachings presented inthe foregoing descriptions and the associated drawings. Therefore, it isto be understood that the disclosure is not to be limited to thespecific implementations disclosed and that modifications and otherimplementations are intended to be included within the scope of theappended claims. Although specific terms are employed herein, they areused in a generic and descriptive sense and not for purposes oflimitation.

What is claimed is:
 1. A method, comprising: measuring downholesaturation pressures of a contaminated fluid over a pumpout volume or apumpout time, wherein the contaminated fluid comprises uncontaminatedfluid and an OBM filtrate; determining a function for the measuredsaturation pressures based on the pumpout volume or pumpout time;extrapolating the function to infinite pumpout volume or infinitepumpout time; determining a saturation pressure for the uncontaminatedfluid at the infinite pumping volume or infinite pumping time; and usinga hypothetical saturation pressure for the OBM filtrate, the saturationpressure for the uncontaminated fluid, and the measured saturationpressure for the contaminated fluid to determine the OBM filtratecontamination.
 2. The method of claim 1, comprising: obtaining asaturation pressure of the OBM filtrate; and determining an OBM filtratecontamination of the contaminated fluid based on the saturation pressurefor the uncontaminated fluid, the saturation pressure for OBM filtrate,and one or more of the measured saturation pressure for the contaminatedfluid.
 3. The method of claim 1, wherein the downhole saturationpressures comprise bubble point pressures and the saturation pressure ofthe uncontaminated fluid comprises a bubble point pressure for theuncontaminated fluid.
 4. The method of claim 1, wherein the saturationpressure of OBM filtrate comprises a bubble point pressure of OBMfiltrate.
 5. The method of claim 1, wherein obtaining a saturationpressure of OBM filtrate comprises assuming a saturation pressure ofzero for OBM filtrate.